Shale Shock: How the Marcellus Shale Transformed the Domestic Natural Gas Landscape and What It Means for Supply in the Years Ahead

Key Takeaways

The Marcellus Shale and Its Impact on U.S. Natural Gas Production

It’s taken well-informed industry observers—Morningstar included—some time to recognize how big of an impact the Marcellus Shale could have on the domestic natural gas landscape.

In the words of one analyst, early predictions about the path of Marcellus production have proven“embarrassingly conservative."

To better understand the key drivers of the Marcellus, we tracked the performance of close to 6,000 wells across Pennsylvania and West Virginia dating back to 2009. Based on our analysis, two character-istics—each somewhat unique to the Marcellus—emerged as likely factors in the industry’s ongoing underestimation of this play: first, the significant improvement in median IP rates, from less than 3 MMcf/d in late 2011 to 5 MMcf/d by mid-2013; second, the ability of these wells to sustain their high rates for a period of several months beyond initial production. See Pages 6–11

We predict the Marcellus shale will be the biggest driver of U.S. gas production over the next few years, adding 3 Bcf/d in 2014 and another 2 Bcf/d in 2015, by which time it will account for close to one fourth of domestic volumes. See Pages 11–14

Supporting our forecast for robust Marcellus growth is the significant backlog of wells awaiting completion and tie-in, which we estimate will take between two and three years to clear. In addition, the pace of infrastructure build-out in the northeastern United States should accommodate production growth, with wet gas processing and takeaway pipeline capacity up more than 200% and 40%, respectively, through 2015. See Pages 15–17

The Marcellus is not immune to declines, with volumes falling by an average of 65% over any given three-year period. When weighing declines against new production, however, the dominant effect—at least through 2015—will be the latter. Incredibly, only 40 or so rigs would be needed to hold Marcellus volumes flat over the next few years. See Pages 14–15

As volumes in the Marcellus have grown, they’ve likely supplanted more expensive sources of gas. Regardless, we don’t believe industrywide marginal cost has been meaningfully affected. See Pages 18–19

We think there exists a handful of plausible explanations for the disconnect between our estimated marginal cost of $5.40 per Mcf and natural gas futures prices that remain far below that level over the next several years. See Page 20

U.S. Natural Gas Production Forecast Through 2015

As part of our forecast, we analyzed seven years’ worth of data contained in the EIA’s newly created Drilling Productivity Report, which tracks key production drivers across the six largest unconventional gas-producing regions in the country. The DPR allows access to data points that were previously unavailable to us, and which, in our opinion, are essential to developing a well-informed production forecast. See Page 21

Our analysis of domestic gas volumes covers the period from January 2007 to December 2015 and includes discrete projections for 12 different gas-producing regions throughout the United States, with a focus on four key variables: dry gas cuts, rig counts, production per rig, and underlying declines. See Pages 22–27

Based on how gas volumes have historically responded to shifts in rig counts, we’ve argued that it would be difficult for industry-wide gas production to remain elevated in the face of a slowdown in drilling activity, as declines eventually overwhelm new production adds. The Marcellus, among other factors, has forced us to re-examine this argument, however. See Pages 22, 24, 26 and 34

Shale gas has been the biggest driver of domestic production over the past several years, helping boost volumes by 14 Bcf/d (or 25%) from 2007-13, to 66 Bcf/d. Growth has been led by unconventional areas like the Marcellus (+9 Bcf/d), Haynesville (+4 Bcf/d), Eagle Ford (+3 Bcf/d), and Barnett and Fayetteville (+2 Bcf/d each), offset by declines in conventional and Gulf of Mexico volumes. Without the Marcellus, it’s probable that domestic natural gas production would have peaked in late2011 or early 2012. See Pages 28–33

Going forward, we expect domestic gas growth to be far less balanced, with only the Marcellus and Eagle Ford exhibiting any meaningful uptick in volumes. We project U.S. natural gas production to increase by approximately 3 Bcf/d (or 4% cumulatively) through 2015, to 69 Bcf/d. See Pages 28–34

With regard to our supply forecast, wild cards to keep an eye on include the emergence of the Utica Shale in Ohio, the ongoing impact of ethane rejection and the pace of processing facility build-outs, natural gas demand (which influences prices and therefore gas-directed drilling activity), and oil prices (which, if they fell to a low enough level, could reduce oil-directed drilling activity and lead to a drop-off in associated gas production). See Pages 35–36

Intersection of Supply & Demand and Investment Conclusions

If over the next few years demand keeps pace with supply as we expect, natural gas prices should normalize between $5 and $6 per Mcf. This is something of a “sweet spot” that serves to incentivize continued gas production while also mitigating the potential for demand destruction. Volatility is likely to remain a defining characteristic of the domestic gas market going forward, however, with seasonal imbalances in supply and demand, especially, contributing to lots of ups and downs in both natural gas prices and stock prices See Pages 37–38

There are several ways investors can take advantage of continued growth in domestic gas production. In the upstream space, we favor Ultra Petroleum (UPL), Tourmaline Oil (TOU), and Canadian Natural Resources (CNQ). Within midstream, we like two names: Spectra Energy Partners (SEP) and Energy Transfer Partners (ETP). For services, we favor Halliburton (HAL), and to slightly lesser degree Schlumberger (SLB). In utilities, if rising natural gas prices lift power prices, several firms stand to benefit, most notably Exelon (EXC), Calpine (CPN), and FirstEnergy (FE). See Pages 38–39

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